Wells – Processes – Producing the well
Reexamination Certificate
2001-02-28
2004-08-31
Bagnell, David (Department: 3672)
Wells
Processes
Producing the well
C166S354000, C166S366000, C405S210000, C405S224400, C114S230130, C441S003000
Reexamination Certificate
active
06782950
ABSTRACT:
TECHNICAL FIELD OF THE INVENTION
The present invention relates to an offshore system for the production of hydrocarbon reserves. More specifically, the present invention relates to an offshore system suitable for deployment in economically and technically challenging environments. Still more specifically, the present invention relates to a control buoy that is used in deepwater operations for offshore hydrocarbon production.
BACKGROUND OF THE INVENTION
In the mid-1950s, the production of oil and gas from oceanic areas was negligible. By the early 1980s, about 14 million barrels per day, or about 25 percent of the world's production, came from offshore wells, and the amount continues to grow. More than 500 offshore drilling and production rigs were at work by the late 1980s at more than 200 offshore locations throughout the world drilling, completing, and maintaining offshore oil wells. Estimates have placed the potential offshore oil resources at about 2 trillion barrels, or about half of the presently known onshore potential oil sources.
It was once thought that only the continental-shelf areas contained potential petroleum resources, but discoveries of oil deposits in deeper waters of the Gulf of Mexico (about 3,000 to 4,000 meters) have changed that view. It is now known that the continental slopes and neighboring seafloor areas contain large oil deposits, thus enhancing potential petroleum reserves of the ocean bottom.
Offshore drilling is not without its drawbacks, however. It is difficult and expensive to drill on the continental shelf and in deeper waters. Deepwater operations typically focus on identifying fields in the area of 100 million bbl or greater because it takes such large reserves to justify the expense of production. Only about 40% of deepwater finds have more than 100 million barrels of recoverable oil equivalent.
As noted above, surface production facilities in deepwater are prohibitively expensive for all but the largest fields. When deepwater fields are produced, a common technique includes the use of a subsea tieback. Using this system, a well is completed and production is piped from the subsea wellhead to a remote existing platform for processing and export. This is by no means an inexpensive process. There are a variety factors involved in a deepwater tieback that make it a costly endeavor, including using twin pipelines to transport production, maintain communication with subsea and subsurface equipment, and perform well intervention using a floating rig.
Twin insulated pipelines, using either pipe-in-pipe and/or conventional insulation, are typically used to tie wells back to production platforms on the shelf in order to facilitate round-trip pigging from the platform. The sea-water temperature at the deepwater wellhead is near the freezing temperature of water, while the production fluid coming out of the ground is under very high pressure with a temperature near the boiling point of water. When the hot production fluids encounter the cold temperature at the seabed two classic problems quickly develop. First, as the production temperature drops below the cloud point, paraffin wax drops out of solution, bonds to the cold walls of the pipeline, restricting flow and causing plugs. As the production fluid continues to cool, the water in the produced fluids begins to form ice crystals around natural gas molecules forming, hydrates and flow is slowed or stopped.
To combat these problems, insulated conventional pipe or pipe-in-pipe, towed bundles with heated pipelines, and other “hot flow” solutions are installed. This does help ensure production, but the cost is very high and some technologies, such as towed bundles, have practical length limits. Such lines can easily cost $1 to $2 million a mile, putting it out of reach of a marginal field budget.
Another problem with extended tiebacks, which is what would exist in ultra deepwater where potential host facilities are easily 60 to 100 miles away, is communication with the subsea and subsurface equipment. Communication and control are traditionally achieved either by direct hydraulics or a combination of hydraulic supply and multiplex systems that uses an electrical signal to actuate a hydraulic system at the remote location. Direct hydraulics over this distance would require expensive, high-pressure steel lines to transport the fluid quickly and efficiently and even then the response time would be in the order of minutes. There also is a problem with degradation of the electrical signal over such lengths. This also interferes with the multiplex system and requires the installation of repeaters along the length. While these problems can be overcome the solutions are not inexpensive.
A third major hurdle to cost-effective deepwater tiebacks is well intervention. A floating rig that can operate in ultra deepwater is not only very expensive, more than $200,000 a day, but also difficult to secure since there are a limited number of such vessels. It doesn't take much imagination to envisage a situation in which an otherwise economically viable project is driven deep into the red by an unexpected workover. Anticipation of such expensive intervention has shelved many deep water projects.
While an overall estimated 40% of deep water finds exceed 100 million bbl, by comparison, only 10% of the fields in the Gulf of Mexico shelf are greater than 100 million barrels of recoverable oil equivalent. Further, 50-100 million bbl fields would be considered respectable if they were located in conventional water depths. The problem with the fields is not the reserves, but the cost of recovering them using traditional approaches, such as the subsea tieback. Hence, it would be desirable to recover reserves as low as 25 million bbl range using economical, non-traditional approaches.
Pigging such a single line system could be accomplished using a subsea pig launcher and/or gel pigs. Gel pigs could be launched down a riser from a work vessel that mixes the gel and through the pipeline system to the host platform. In the case of a planned shut-in, the downhole tubing and flowline can be treated with methanol or glycol to avoid hydrate formation to in the stagnant flow condition.
Hence a suitable device for the storage of methanol (for injection) and gel for pigging, as well as pigging and workover equipment, is desired. The preferred devices would be an unmanned control buoy moored above the subsea wells. Further, it is desirable to provide a device that is capable of supporting control and storage equipment in the immediate vicinity of subsea wells.
SUMMARY OF THE INVENTION
The present invention relates to a wellhead control buoy that is used in deepwater operations for offshore hydrocarbon production. The wellhead control buoy is preferably a robust device, easy to construct and maintain. One feature of the present invention is that the wellhead control buoy, also referred to herein as the wave-rider buoy, is suitable for benign environments such as West Africa. Additionally, the present invention is suitable for environments, such as the Gulf of Mexico, in which it is typically the policy to shut down and evacuate facilities during hurricane events.
The wave-rider buoy is so termed because it is a pancake-shaped buoy that rides the waves. The preferred wave-rider buoy is a weighted and covered, shallow but large diameter cylinder, relatively simple to fabricate, robust against changes in equipment weight, relatively insensitive to changes in operational loads, easy for maintenance access, and relatively insensitive to water depth. The wave-rider buoy can be effectively used in water depths up to 3,000 meters using synthetic moorings, and is particularly suitable for use in water depths of at least 1,000 meters. The wave-rider buoy may be used with or without an umbilical from the main platform. An alternate embodiment of the present invention includes a power system located on the buoy.
Important features of the wave-rider buoy include its
1) hull form—similar to a barge and easy to construct,
2) mooring system—cate
Amin Rajnikant M.
Gray David A.
O'Sullivan James F.
Bagnell David
Conley & Rose, P.C.
Gay Jennifer H
Kellogg Brown & Root, Inc.
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